Heavy hydrocarbon removal from lean gas to lng liquefaction

ABSTRACT

A system for processing a gas stream can include a physical solvent unit, an acid gas removal unit upstream or downstream of the physical solvent unit, and an LNG liquefaction unit downstream of the acid gas removal unit. The physical solvent unit is configured to receive a feed gas, remove at least a portion of any C5+ hydrocarbons in the feed gas stream using a physical solvent, and produce a cleaned gas stream comprising the feed gas stream with the portion of the C5+ hydrocarbons removed. The acid gas removal unit is configured to receive the cleaned gas stream, remove at least a portion of any acid gases present in the cleaned gas stream, and produce a treated gas stream. The LNG liquefaction unit is configured to receive the treated gas stream and liquefy at least a portion of the hydrocarbons in the treated gas stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.15/209,015, filed on Jul. 13, 2016, entitled “Heavy Hydrocarbon Removalfrom Lean Gas to LNG Liquefaction”, which is incorporated herein byreference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Natural gas is available from conventional natural gas reservoirs andunconventional gas, such as shale gas, tight gas and coal bed methane.Lean natural gas feeds (very high methane content) are becoming moreprevalent, especially in many parts of the world including NorthAmerica, East Africa, and Australia. These feed gases often contain somearomatics and heavy hydrocarbons that freeze out at liquefactiontemperature causing plant shutdown and revenue losses. Therefore, thesecomponents must be removed prior to liquefaction.

SUMMARY

In an embodiment, a system for processing a gas stream can include aphysical solvent unit, an acid gas removal unit downstream of thephysical solvent unit, and an LNG liquefaction unit downstream of theacid gas removal unit. The physical solvent unit is configured toreceive a feed gas, remove at least a portion of any C₅₊ hydrocarbons inthe feed gas stream using a physical solvent, and produce a cleaned gasstream comprising the feed gas stream with the portion of the C₅₊hydrocarbons removed. The acid gas removal unit is configured to receivethe cleaned gas stream, remove at least a portion of any acid gasespresent in the cleaned gas stream, and produce a treated gas stream. TheLNG liquefaction unit is configured to receive the treated gas streamand liquefy at least a portion of the hydrocarbons in the treated gasstream.

In an embodiment, a system for processing a gas stream can include anacid gas removal unit, a physical solvent unit downstream of the acidgas removal unit, and an LNG liquefaction unit downstream of thephysical solvent unit. The acid gas removal unit is configured toreceive a feed gas stream, remove at least a portion of any acid gasespresent in the feed gas stream, and produce a cleaned gas stream. Thephysical solvent unit is configured to receive the cleaned gas stream,remove at least a portion of any C₅₊ hydrocarbons in the cleaned gasstream, and produce a treated gas stream comprising the cleaned gasstream with the portion of the C₅₊ hydrocarbons removed. The LNGliquefaction unit is configured to receive the treated gas stream andliquefy at least a portion of the hydrocarbons in the treated gasstream.

In an embodiment, a method of processing a gas stream can includecontacting a gas stream with a physical solvent, wherein the gas streamcomprises C₁ hydrocarbons, C₂ hydrocarbons, C₃ hydrocarbons, C₄hydrocarbons, C₅ hydrocarbons, C₅₊ hydrocarbons, and acid gascomponents, removing at least a portion of the C₃₊ hydrocarbons based onthe contacting with the physical solvent, contacting the gas stream witha solvent, removing at least a portion of the acid gas components basedon the contacting with the physical solvent, and liquefying at least aportion of the gas stream after contacting the gas stream with thephysical solvent and the solvent.

These and other features will be more clearly understood from thefollowing detailed description taken in conjunction with theaccompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure, referenceis now made to the following brief description, taken in connection withthe accompanying drawings and detailed description, wherein likereference numerals represent like parts.

FIG. 1 is an exemplary configuration of an LNG liquefaction plant usingNGL recovery with turbo expander for the removal of heavy hydrocarbonand aromatics.

FIG. 2 is an exemplary configuration of an LNG liquefaction plant usinga scrub column for the removal of heavy hydrocarbon and aromatics.

FIG. 3 is an exemplary configuration of an LNG liquefaction plant usingthe Thermal Swing Adsorption process for the removal of heavyhydrocarbon and aromatics.

FIG. 4 is an exemplary configuration of an LNG liquefaction plant ofusing a physical solvent located downstream of the acid gas removal unitfor the removal of heavy hydrocarbon and aromatics.

FIG. 5 is an exemplary configuration of an LNG liquefaction plant usinga physical solvent located upstream of the acid gas removal unit for theremoval of water in addition to heavy hydrocarbon and aromatics.

FIG. 6 is a configuration of a physical solvent unit for the removal ofheavy hydrocarbon and aromatics.

FIG. 7 is another configuration of a physical solvent unit for theremoval of heavy hydrocarbon and aromatics.

DETAILED DESCRIPTION

It should be understood at the outset that although illustrativeimplementations of one or more embodiments are illustrated below, thedisclosed systems and methods may be implemented using any number oftechniques, whether currently known or not yet in existence. Thedisclosure should in no way be limited to the illustrativeimplementations, drawings, and techniques illustrated below, but may bemodified within the scope of the appended claims along with their fullscope of equivalents.

The following brief definition of terms shall apply throughout theapplication:

The term “comprising” means including but not limited to, and should beinterpreted in the manner it is typically used in the patent context;

The phrases “in one embodiment,” “according to one embodiment,” and thelike generally mean that the particular feature, structure, orcharacteristic following the phrase may be included in at least oneembodiment, and may be included in more than one embodiment of thepresent systems and methods (importantly, such phrases do notnecessarily refer to the same embodiment);

If the specification describes something as “exemplary” or an “example,”it should be understood that refers to a non-exclusive example;

The terms “about” or “approximately” or the like, when used with anumber, may mean that specific number, or alternatively, a range inproximity to the specific number, as understood by persons of skill inthe art field; and

If the specification states a component or feature “may,” “can,”“could,” “should,” “would,” “preferably,” “possibly,” “typically,”“optionally,” “for example,” “often,” or “might” (or other suchlanguage) be included or have a characteristic, that particularcomponent or feature is not required to be included or to have thecharacteristic. Such component or feature may be optionally included insome embodiments, or it may be excluded.

Disclosed herein are systems and methods to reduce the level of heavyhydrocarbons such as aromatics in a lean natural gas feed to an LNGliquefaction plant using a physical solvent in a physical solvent unit.In general, some natural gas reservoirs are naturally lean and containonly small amounts of C₂₊ components. However, a small amount ofaromatics (e.g. BTX—Benzene, Toluene, and Xylene) and C₅₊ often remainin the gas. These components must be removed to very low levels (1 ppmvfor BTX, 0.1% for C₅₊ and approximately 150 ppmv for C₆₊) to avoidfreezing in the liquefaction equipment for typical LNG productspecifications.

Pipeline gas is typically processed, as a minimum, to meet the sales gasheating value specifications using cryogenic processing for C₃₊ removalor by mechanical refrigeration for C₅₊ removal. When mechanicalrefrigeration unit is used, only a portion of the C₅₊ is removed,producing a residue gas that contains C₅₊ hydrocarbons that are higherthan feed gas specifications to LNG liquefaction plants, and must beprocessed in order to avoid freezing in the LNG liquefaction plants.

Table 1 provides an embodiment of a typical pipeline gas composition,and Table 2 shows an exemplary upper limit of the C₅₊ and aromaticscomponents to an LNG liquefaction plant. The allowable limits of heavyhydrocarbons in the LNG plant vary depending on the liquefactiontechnology and process conditions. In most cases, the heavy hydrocarbonsand benzene must be removed to below the concentration shown in Table 2.

TABLE 1 Typical Pipeline Gas Composition Component Mole % CO₂ 2.0001 H₂S0.0004 COS 0.0010 H₂ 0.0100 N₂ 0.2500 AR 0.0174 O₂ 0.0010 CH₄ 88.4279C₂H₆ 8.0003 C₃H₈ 0.7788 N—C₄H₁₀ 0.1404 I—C₄H₁₀ 0.1644 N—C₅H₁₂ 0.0390I—C₅H₁₂ 0.0624 C₆H₁₄ 0.0660 C₇H₁₆ 0.0140 Benzene 250 ppm

TABLE 2 Exemplary upper Limit of hydrocarbons to liquefaction plantCOMPONENT ppmv C₅+ 1000 C₆ 100 C₇ 10 C₈ 1 Benzene 1

There are many technologies that can be used for heavy hydrocarbonremoval from natural gas streams. If the gas is rich with a substantialamount of the C₃₊ components, such as gas with propane liquid greaterthan about 2 to 3 GPM (gallons of propane plus liquid per thousandstandard cubic feet of gas), an NGL recovery process can typically beused. NGL can generate more revenue than natural gas on a Btu valuebasis, and may be economically justified. If NGL recovery cannot bejustified, the heavy hydrocarbon content must still need to be removedby chilling and condensing in order to meet the sales gas heating valuespecifications.

The NGL recovery expander plant application is shown in FIG. 1. Feed gasstream 1, which can be supplied at about 1000 psig, can be treated in anacid gas removal unit 52 for acid gas removal (e.g., CO₂, H₂S, etc.removal) to meet an inlet gas specification (e.g., in some aspects, aninlet gas specification, such as a 50 ppmv CO₂ upper limit) set by anLNG plant 54. The CO₂ can be removed as stream 3. The resulting treatedstream 6 from the acid gas removal unit 52 can be further processed inthe dehydration unit 53 (e.g., a molecular sieve unit, etc.) for waterremoval to a level below about 0.1 ppmv and/or mercury removal to at orbelow about 10 nanogram/m³. The water and/or mercury can leave in stream4. The dried and treated gas in stream 7 can then be processed in theNGL recovery plant 11 to produce the C₃₊ NGL liquid stream 2 and a leanresidual gas stream 8 as feed to LNG liquefaction plant 54.

For lean feed gas, (e.g., feed gas with about 2 GPM C₃₊ content), aconventional scrub column can be used. The high pressure feed gas isreduced in pressure to below its critical pressure, in order to operatewith the scrub column. The residual gas from the scrub column must berecompressed back to 1000 psig to feed the LNG liquefaction process,which significantly increases the power consumption and reducesliquefaction efficiency of the liquefaction plant. The scrub columnprocess is further illustrated in FIG. 2. In this option, the feed gasstream 1 is treated in the acid gas removal unit 52 and the dehydrationand mercury removal unit 53, similar to FIG. 1.

In the scrub column configuration, the treated gas stream 7 from thedehydration and mercury removal unit 53 can be let down in pressure andcooled in a heat exchanger 25 (e.g., a propane chiller) to about −25° F.to form cooled stream 22. The cooled stream 22 can then be fed to ascrub column 21, which can operate at about 600 psig pressure. The scrubcolumn 21 can use propane refrigeration to generate reflux and produce abottom C₃₊ product stream 29 containing the heavy hydrocarbons and alean overhead gas stream 28 suitable for the liquefaction plant. Thelean overhead gas stream can be recompressed by compressor 26 asrequired by the liquefaction plant 54.

The main disadvantage of this configuration shown in FIG. 2 is that highpressure feed gas must be reduced in pressure to operate the scrubcolumn. While the letdown energy can be recovered with the use of aturbo expander, the energy required to recompress the overhead vapor tothe liquefaction plant can be significant. On the other hand, if thefeed gas is lean, for example, with less than 1 GPM C₃₊ content, thefeed gas may not contain sufficient C₃₊ to generate reflux for a stablescrub column operation. Such instability will result in heavyhydrocarbon slippage to the overhead gas resulting in freezing of theliquefaction exchangers.

For very lean gases, especially ones where most of the NGLs have alreadybeen extracted from pipeline gas, the primary purpose of the upstreamprocessing unit is the removal of the C₅₊ and aromatic hydrocarbons toprevent freezing in the downstream LNG section. The application of theprevious two technologies may not be a cost effective solution.

Another method to remove heavy hydrocarbons and aromatics from lean gasfeed is by the Thermal Swing Adsorption (TSA) process 31 as shown inFIG. 3. TSA operation employs molecular sieves that are specificallydesigned to remove heavy hydrocarbons and aromatics in a byproductstream 32. The process operates in a cyclic fashion, similar to thedehydration unit. Unlike other technologies, the adsorption process canbe carried out at the feed pressure and has no pressure reduction. TheTSA process requires a high temperature—typically around or above 600°F.—for sieve regeneration. The high temperature is problematic withheavy hydrocarbons due to the potential coking problems, especially inthe presence of oxygen frequently found in pipeline gas. Fired heatermay cause coking or combustion problems at these high temperatures. Tooperate such system, a fired heater should not be used due to thepotential for coking and fouling, and instead, high pressure steam(e.g., 1700 psig steam) or a hot oil system must be made available,which requires additional equipment, and increased capital and operatingexpenses. In addition, the process also requires propane refrigerationfor condensation of the heavy hydrocarbons and subsequent removal fromthe regeneration gas. While the TSA system can eliminate therecompression requirement, high capital and operating costs and theinherent coking problems are limitations to the use of this process.

All or almost all of these systems and methods suffer from one or moredisadvantages. Described herein is a more cost-efficient and effectivemethod for heavy hydrocarbon and benzene removal to lean feed gases toLNG liquefaction plants. Specifically, the present systems and methodsare directed to configurations and methods of removal of heavyhydrocarbons and aromatics from a lean feed gas (e.g., feed gas with 1to 2 GPM or lower C₃₊ liquid content) with the use of a physicalsolvent. In some aspects, heavy hydrocarbons can be removed from apipeline lean gas operating at pipeline pressure (e.g., between about900 psig to about 1500 psig).

In some aspects, the physical solvent unit 41 can be located upstream ofthe acid gas removal unit 52 as shown in FIG. 4. As shown in FIG. 4, thefeed gas stream 1, which can be supplied at about 1000 psig, can firstpass to the physical solvent unit 41. The feed gas stream 1 can compriseany hydrocarbon stream having a heavy hydrocarbon composition above thefeed composition limits to the LNG liquefaction plant 54. In someembodiments, the feed gas stream 1 can have a BTX composition aboveabout 1 ppmv, or have a C₅₊ composition above about 0.1%, and/or have aC₆₊ composition above approximately 150 ppmv. In some embodiments, thefeed gas can comprise a pipeline gas (e.g., a pipeline gas having acomposition as shown in Table 1).

The feed gas stream 1 can pass to the physical solvent unit 41. Thephysical solvent unit 41 can comprise any unit suitable for contacting aphysical solvent with the feed gas stream 1. The physical solvent unit41 can produce a cleaned gas stream 46 having a reduced heavyhydrocarbon concentration and a heavy hydrocarbon stream 43 with theremoved heavy hydrocarbons from the feed gas stream 1 (e.g., having anincreased concentration of the heavy hydrocarbons from the feed gasstream 1). Within the physical solvent unit 41, the physical solvent cancontact the feed gas stream and extract at least a portion of the heavyhydrocarbons. The contacting can then produce the cleaned gas stream 46and a rich solvent stream within the physical solvent unit. Theresulting rich physical solvent can be treated with low pressure steamand extraction with water to release at least a portion of the extractedheavy hydrocarbons in an extractor, resulting in a the heavy hydrocarbonstream 43 and a lean solvent, which can be recycled for contact with thefeed gas stream 1. Excess water can be removed from the regeneratoroverhead system. The physical solvent unit 41 can operate atapproximately ambient, or slightly below ambient, temperatures. Forexample, an absorber column in the physical solvent unit can operate ata temperature between about 50° F. to about 120° F., or between about70° F. and about 100° F. Exemplary physical solvent systems aredescribed in more detail herein with respect to FIGS. 6 and 7.

The physical solvent used within the physical solvent unit 41 cancomprise any physical solvent having an affinity towards heavyhydrocarbons and aromatics. The physical solvent can comprise DEPG(dimethylether of polyethylene glycol), ethylene carbonate, propylenecarbonate, N-methylpyrrolidone, glycol ethers, ethers of polyglycols(e.g., dimethoxytetraethylene glycol), N-substituted morpholine, highmolecular weight glycols such as triethylene glycol, isobutylene glycol,and/or mixtures of these physical solvents.

In some aspects, the physical solvent can remove C₅ hydrocarbons, C₆hydrocarbons, C₇+ hydrocarbons, benzene, toluene, and/or xylene. In someaspects, the physical solvent can remove between about 20% and about 40%of the C₅ hydrocarbons in the feed gas stream under operatingconditions. In some aspects, the physical solvent can remove betweenabout 30% and 70% of the C₆ hydrocarbons in the feed gas stream underoperating conditions. In some aspects, the physical solvent can removebetween about 90% and 99% of the C₇₊ hydrocarbons in the feed gas streamunder operating conditions. In some aspects, the physical solvent canremove greater than 90%, greater than 95%, greater than 96%, greaterthan 97%, greater than 98%, greater than 99%, greater than 99.9%, orgreater than 99.99% of the benzene and/or other aromatic hydrocarbons inthe feed gas stream 1 under operating conditions.

As shown in FIG. 4, the resulting cleaned gas stream 46 can then pass tothe acid gas removal unit 52, which may operate using a tertiary amine(e.g., activated dimethylethanolamine (MDEA)), a primary amine (e.g.,DGA), or another suitable solvent. The acid gas removal unit 52 canserve to remove CO₂ and H₂S to meet the feed gas CO₂ specification forthe LNG liquefaction plant (e.g., less than or equal to 50 ppmv CO₂). Insome aspects, an acid gas removal unit 52 can comprise an absorber and astripper, where a lean solvent contacts the gas to be treated in theabsorber to absorb at least a portion of any acid gases present in theinlet gas stream. The resulting rich solvent can then be regenerated inthe stripper using an increased temperature to release the acid gasesand produce the lean solvent to be recycled to the absorber. The acidgases can be further processed to comply with emission regulations,using incineration, sulfur recovery, or reinjection to reservoirs.

The solvents used in the acid gas removal unit 52 are chemical reactionbased solvent such as activated MDEA, formulated MDEA, MEA and DGA, orother amine solvents that form chemical bonds with acid gases. In allembodiments, the solvent used in the physical solvent unit 41 are basedon their affinity towards heavy hydrocarbons (Henry's law of absorption)at operating pressure and there are no chemical reactions. The acid gasremoval unit 52 can remove acid gases from the feed gas and produce anacid gas stream 3 that can be processed downstream to comply withemission regulations. The treated gas stream can then pass to thedehydration and mercury removal system 53 for removal of water andmercury, and then to the LNG liquefaction unit 54 as described abovewith respect to FIGS. 1 and 2. In all embodiments, the acid gas removalunit 52 removes the acid gas content in the feed gas to meet 50 ppmv ofCO₂ and 4 ppmvH₂S required for LNG production.

As shown in FIG. 4, the physical solvent unit 41 can be placed upstreamof the acid gas removal unit 52. When placed upstream of the acid gasremoval unit 52, the physical solvent unit 41 can remove the heavyhydrocarbons, such as benzene and other aromatics, and reduce thefoaming tendency of the solvent used in the acid gas removal unit 52.This may beneficially reduce or eliminate the operating problemsassociated with heavy hydrocarbon foaming. Further, the physical solventused in the physical solvent unit 41 may have a tendency to remove atleast a portion of the acid gases in the feed gas stream 1 prior to thecleaned gas in stream 46 passing to the acid gas removal unit 52. Forexample, in some aspects, between about 10% and about 30% of the acidgases present in the feed gas stream 1 can be removed with the heavyhydrocarbons in stream 43 in the physical solvent unit 41. This mayallow the acid gas removal unit 52 to be reduced in size or capacity,thereby reducing the capital costs and operating requirements of theacid gas removal unit 52.

The location of the physical solvent unit 41 can be upstream ordownstream of the acid gas removal unit 52. As shown in FIG. 5, thephysical solvent unit 41 can be placed downstream of the acid gasremoval unit 52. Each of the units shown in FIG. 5 can perform the samefunctions and use the same solvents and the like as described withrespect to any of the similarly described units in FIGS. 1-4. Whenplaced downstream of the acid gas removal unit 52, the physical solventunit 41 can remove water in addition to heavy hydrocarbons. In someaspects, the water content of the stream passing from the acid gasremoval unit 52 to the physical solvent unit 41 can be reduced to belowabout 1 lb/MMscf in the physical solvent unit 41. This can reduce thedehydration duty in the dehydration unit 53. In this configuration, theheat exchangers, such as propane chillers, that are used to reduce thewater content of the stream passing to the dehydration unit 53 can bedownsized or eliminated, which can lower the capital and operating costof the dehydration unit.

Whether the physical solvent unit 41 is placed upstream or downstream ofthe acid gas removal unit 52, the use of a physical solvent in thephysical solvent unit 41 can be configured to remove heavy hydrocarbonsand aromatics to reduce or eliminate the freezing problems in the LNGliquefaction plant 54.

An exemplary embodiment of a physical solvent unit 60 is shown in FIG.6. The physical solvent unit 60 shown in FIG. 6 can be used as thephysical solvent unit 41 in any of the embodiments of FIG. 4 or 5. Asshown in FIG. 6, the feed gas stream 1 can enter the physical solventunit 60 at a pressure between about 800 psia and about 1,100 psia and ata temperature of between about 90° F. and about 150° F. While the feedgas stream 1 is shown as entering the physical solvent unit 60, thephysical solvent unit 60 can also be fluidly coupled downstream of anacid gas removal unit, in which configuration the gas stream enteringthe physical solvent unit 60 would be the treated gas from the acid gasremoval unit (e.g., in the embodiment shown in FIG. 5). The feed gasstream 1 can have any of the compositions described herein includinghaving heavy hydrocarbon composition above the feed specifications foran LNG liquefaction plant. Further, the physical solvent used within thephysical solvent unit 60 can comprise any of those physical solvents, orany combination thereof, described herein.

The feed gas stream 1 can pass into a lower portion of an absorber 61,and can be scrubbed with lean solvent 84 entering in an upper portion ofthe absorber 61. Within the absorber 61, the feed gas 1 can contact thelean solvent 84 and at least a portion of the heavy hydrocarbons,aromatics, and water (and optionally at least a portion of any acidgases, such as CO₂ and/or H₂S present in the feed gas stream 1) can betransferred to the lean solvent 84 to produce the rich solvent stream 62leaving the bottom of the absorber 61.

The treated gas can leave the absorber 61 as overhead stream 80 and becooled in an optional heat exchanger 81 to form a two-phase stream priorto entering flash drum 82. The treated gas can pass out of the flashdrum 82 as overhead stream 99. The treated gas in stream 99 can thenpass to any of the downstream units described above, such as the acidgas removal unit (if the physical solvent unit is upstream of the acidgas removal unit), the dehydration unit, and/or the LNG liquefactionplant. A bottoms stream 83 from the flash drum 82 can pass to the inletto the stripper column 74, for example, by being combined with the richsolvent stream downstream of the heat exchanger 68.

The rich solvent with the absorbed hydrocarbons and aromatics leaves theabsorber bottom as rich solvent stream 62 and can be let down inpressure in valve 63 to form a two phase stream 65. Stream 65 can thenpass to a rich solvent flash drum 64 operating at between about 80 psiand about 150 psia. The flashed vapor stream 66 from the rich solventflash drum 64 can be routed to a number of downstream uses, such as afuel gas recovery system. A flashed liquid stream 67 from the richsolvent flash drum 64 can be heated in the lean/rich heat exchanger 68to a temperature between about 250° F. and about 300° F. before beingfed to the stripper column 74.

The stripper column 74 can produce an overhead vapor 75 that can be atleast partially condensed in an ambient cooler 76 and passed to a flashdrum 79. A waste gas stream 42 containing the H₂S, CO₂, hydrocarbons,aromatics and water are removed from the overhead of the flash drum 79.A flashed liquid stream 78 containing mainly water can pass out of theflash drum 79 as the bottoms stream. A first portion of the flashedliquid stream 78 can be pumped by pump 77 as reflux back to the strippercolumn 74, and excess water can be purged from the stripper column 74overhead as stream 78 a. Removal of water from the feed gas using thephysical solvent can be used to produce a dried gas from the absorber61, which can significantly reduce the dehydration duty in thedownstream dehydration unit.

The stripper column 74 can be heated with low pressure steam stream 72using the bottom reboiler 73. The bottom stream 71 can be at atemperature between about 280° F. and 310° F. and can be pumped by asolvent pump 70 to form stream 69 at a pressure between about 80 psia toabout 120 psia and cooled in the lean/rich heat exchanger 68 to formstream 93 at a temperature between about 140° F. and about 180° F. Thelean solvent stream 93 can be further cooled in a lean air cooler 92 toa temperature between about 90° F. and about 110° F. to form cooledstream 91 prior to being pumped by pump 90 and recycled back to theabsorber 61.

In instances in which the feed gas contains a significant amount ofheavy hydrocarbon (e.g. greater than about 0.1 mole %), any excess heavyhydrocarbons in the lean solvent stream 93 can be purged by a slipstream of the lean solvent stream 89 being routed to a hydrocarbonextraction column 88. A water steam 86 can be used as the extractionagent to produce a hydrocarbon overhead stream 85 that can be removedfrom the circuit to avoid buildup of the hydrocarbons in the loop. Whenthe heavy hydrocarbons in the feed gas are present at a lowconcentration (e.g. C₆₊ less than 0.01 mole %), the hydrocarbonextractor 88 may not be needed, or if present, not used. The solventstream 87 can be returned to the solvent system.

Another exemplary embodiment of a physical solvent unit 70 isillustrated in FIG. 7. The physical solvent unit 70 is similar to thephysical solvent unit 60 described with respect to FIG. 6, and thesimilar components will not be described in detail in the interest ofbrevity. The main difference between the physical solvent unit 70 andthe physical solvent unit 60 is in the inclusion of a wash section inthe upper section of the absorber 110 in the physical solvent unit 70.The wash section can reduce the solvent losses by circulation waterusing a packed section, while saturating the treated gas with water.Such configuration is especially advantageous when the acid gas removedunit is located downstream (FIG. 4), which can reduce or even eliminatewater makeup to the acid gas removal unit. In the physical solvent unit70, the feed gas stream 1 can enter the absorber 110 and be scrubbedwith a lean solvent entering the absorber 110 in stream 84. The treatedoverhead vapor stream can be further scrubbed with circulating watersteam 103 being pumped around using pump 102. A water makeup stream 101can be added to the top of the absorber 110 as needed for water balance.The rich solvent with the absorbed hydrocarbons and aromatics can passout of the absorber 110 as the bottoms stream. The remainder of thesolvent regeneration loop can be similar to or the same as the solventregeneration loop described with respect to FIG. 6. The overhead cleanedgas stream 80 can pass out of the absorber 110 as the overhead streamand be processed as described with respect to FIG. 6.

In each configuration of the physical solvent unit, the physical solvent(e.g., any of those described herein) can be used to remove at least aportion of the heavy hydrocarbons from a feed gas stream, acid gases,and optionally water to reduce the load on a downstream acid gas removalsystem and/or dehydration system.

Example

The disclosure having been generally described, the following examplesis given as particular embodiments of the disclosure and to demonstratethe practice and advantages thereof. It is understood that the examplesare given by way of illustration and are not intended to limit thespecification or the claims in any manner.

A physical solvent unit operation was modeled using Fluor's proprietarysimulation software EconoSolv Ver.16 which was developed based on aproprietary data base for the DEPG solvent according to the process flowdiagram shown in FIG. 7. The model was conducted using DEPG as thephysical solvent and a feed gas composition as shown below in Table 3.The resulting process conditions including the stream compositions ofseveral streams (in mole fractions unless noted otherwise) and thestream conditions (e.g., temperature, pressure, flowrate, etc.) areshown in Table 3.

Flash Water Feed Treated Gas Makeup Stream Gas (1) Gas (99) (42 + 66)(101) Temperature [F] 115 112 121 100 Pressure [psia] 937 932 20 1,000Molar Flow [lbmole/hr] 90,459 89,677 1,067 296 Mass Flow [lb/hr]1,646,806 1,622,848 29,102 5,333 Master Comp Mole Frac (CO2) 0.0200980.018872 0.117697 — Master Comp Mole Frac (H2S) 0.000004 0.0000030.000117 — Master Comp Mole Frac (COS) 0.000000 0.000000 0.000000 —Master Comp Mole Frac (H2) 0.000100 0.000101 0.000011 — Master Comp MoleFrac (N2) 0.002512 0.002527 0.000573 — Master Comp Mole Frac (AR)0.000175 0.000176 0.000042 — Master Comp Mole Frac (O2) 0.0000100.000010 0.000003 — Master Comp Mole Frac (CH4) 0.884292 0.8856250.535851 — Master Comp Mole Frac (C2H6) 0.080390 0.078896 0.184459 —Master Comp Mole Frac (C3H8) 0.007828 0.007450 0.037509 — Master CompMole Frac (N—C4H10) 0.001407 0.001295 0.010467 — Master Comp Mole Frac(I—C4H10) 0.001648 0.001529 0.011208 — Master Comp Mole Frac (N—C5H12)0.000372 0.000283 0.007765 — Master Comp Mole Frac (I—C5H12) 0.0006230.000518 0.009269 — Master Comp Mole Frac (C6H14) 0.000211 0.0001060.008955 — Master Comp Mole Frac (C7H16) 0.000042 0.000006 0.003092 —Master Comp Mole Frac (C8H18) 0.000012 0.000000 0.001012 — Master CompMole Frac (C9H20) 0.000008 0.000000 0.000681 — Master Comp Mole Frac(CH3SH) 0.000000 0.000000 0.000002 — Master Comp Mole Frac (BENZENE)0.000121 0.000000 0.010225 — Master Comp Mole Frac (TOLUENE) 0.0000840.000003 0.006885 — Master Comp Mole Frac (M-XYLENE) 0.000006 0.0000000.000483 — Master Comp Mole Frac (P-XYLENE) 0.000006 0.000000 0.000496 —Master Comp Mole Frac (THIOPHEN) 0.000000 0.000000 0.000002 — MasterComp Mole Frac (WATER) 0.000050 0.002599 0.053195 1.000000

Thus, the model predicts that the physical solvent unit can remove theheavy hydrocarbons to a level suitable to meet the LNG liquefactionplant inlet specifications as well as removing a portion of the acidgases present in the feed stream, which can reduce the load on anydownstream acid gas removal unit.

Having described various systems and methods herein, various embodimentscan include, but are not limited to:

In a first embodiment, a system for processing a gas stream comprises: aphysical solvent unit, wherein the physical solvent unit is configuredto receive a feed gas, remove at least a portion of the C₅₊ hydrocarbonsand aromatic hydrocarbons in the feed gas stream using a physicalsolvent, and produce a cleaned gas stream comprising the feed gas streamwith the portion of the C₅₊ and aromatic hydrocarbons removed; an acidgas removal unit downstream of the physical solvent unit, wherein theacid gas removal unit is configured to receive the cleaned gas stream,remove at least a portion of any acid gases present in the cleaned gasstream, and produce a treated gas stream; and an LNG liquefaction unitdownstream of the acid gas removal unit, wherein the LNG liquefactionunit is configured to receive the treated gas stream and liquefy atleast a portion of the hydrocarbons in the treated gas stream.

A second embodiment can include the system of the first embodiment,further comprising: a dehydration unit downstream of the acid gasremoval unit and upstream of the LNG liquefaction unit, wherein thedehydration unit is configured to remove at least a portion of the waterpresent in the treated gas stream prior to the treated gas streampassing to the LNG liquefaction unit. A mercury removal unit can also bepresent to remove almost all of the mercury content in the treated gas.

A third embodiment can include the system of the first or secondembodiment, wherein the physical solvent unit is configured to producethe cleaned gas stream having a benzene, toluene, and xylene compositionbelow about 1 ppmv.

A fourth embodiment can include the system of any of the first to thirdembodiments, wherein the physical solvent unit is configured to producethe cleaned gas stream having a C₅₊ composition below about 0.1% byvolume.

A fifth embodiment can include the system of any of the first to fourthembodiments, wherein the physical solvent unit is configured to producethe cleaned gas stream having a C₆₊ composition below about 150 ppmv.

A sixth embodiment can include the system of any of the first to fifthembodiments, further comprising the feed gas, wherein the feed gas has aC₃₊ composition below about 2 to 3 GPM.

A seventh embodiment can include the system of any of the first to sixthembodiments, further comprising the physical solvent, wherein thephysical solvent comprises dimethylether of polyethylene glycol,ethylene carbonate, propylene carbonate, N-methylpyrrolidone, glycolethers, ethers of polyglycols, N-substituted morpholine, or anycombination thereof.

An eighth embodiment can include the system of any of the first toseventh embodiments, wherein the physical solvent unit is configured toremove at least a portion of any water present in the feed gas.

A ninth embodiment can include the system of any of the first to eighthembodiments, wherein the physical solvent unit is configured to producethe cleaned gas stream having a water composition at or below about 1lb/MMscf.

In a tenth embodiment, a system for processing a gas stream comprises:an acid gas removal unit, wherein the acid gas removal unit isconfigured to receive a feed gas stream, remove at least a portion ofany acid gases present in the feed gas stream, and produce a cleaned gasstream; a physical solvent unit downstream of the acid gas removal unit,wherein the physical solvent unit is configured to receive the cleanedgas stream, remove at least a portion of any C₅₊ hydrocarbons in thecleaned gas stream, and produce a treated gas stream comprising thecleaned gas stream with the portion of the C₅₊ hydrocarbons removed; andan LNG liquefaction unit downstream of the physical solvent unit,wherein the LNG liquefaction unit is configured to receive the treatedgas stream and liquefy at least a portion of the hydrocarbons in thetreated gas stream.

An eleventh embodiment can include the system of the tenth embodiment,further comprising: a dehydration unit downstream of the acid gasremoval unit and upstream of the LNG liquefaction unit, wherein thedehydration unit is configured to receive the treated gas stream andremove at least a portion of the water present in the treated gas streamprior to the cleaned gas stream passing to the LNG liquefaction unit.

A twelfth embodiment can include the system of the tenth or eleventhembodiment, wherein the physical solvent unit is configured to producethe cleaned gas stream having a benzene, toluene, and xylene compositionbelow about 1 ppmv.

A thirteenth embodiment can include the system of any of the tenth totwelfth embodiments, wherein the physical solvent unit is configured toproduce the cleaned gas stream having a C₅₊ composition below about 0.1%by volume.

A fourteenth embodiment can include the system of any of the tenth tothirteenth embodiments, wherein the physical solvent unit is configuredto produce the cleaned gas stream having a C₆₊ composition below about150 ppmv.

A fifteenth embodiment can include the system of any of the tenth tofourteenth embodiments, further comprising the feed gas, wherein thefeed gas has a C₂₊ composition below about 2 to 3 GPM.

A sixteenth embodiment can include the system of any of the tenth tofifteenth embodiments, further comprising the physical solvent, whereinthe physical solvent comprises dimethylether of polyethylene glycol,ethylene carbonate, propylene carbonate, N-methylpyrrolidone, glycolethers, ethers of polyglycols, N-substituted morpholine, or anycombination thereof.

A seventeenth embodiment can include the system of any of the tenth tosixteenth embodiments, wherein the physical solvent unit is configuredto remove at least a portion of any water present in the feed gas.

An eighteenth embodiment can include the system of any of the tenth toseventeenth embodiments, wherein the physical solvent unit is configuredto produce the cleaned gas stream having a water composition at or belowabout 1 lb/MMscf.

In a nineteenth embodiment, a method of processing a gas streamcomprises: contacting a gas stream with a physical solvent, wherein thegas stream comprises C₁ hydrocarbons, C₂ hydrocarbons, C₃ hydrocarbons,C₄ hydrocarbons, C₅₊ hydrocarbons, and acid gas components; removing atleast a portion of the C₅₊ hydrocarbons based on the contacting with thephysical solvent; contacting the gas stream with a solvent; removing atleast a portion of the acid gas components based on the contacting withthe physical solvent; and liquefying at least a portion of the gasstream after contacting the gas stream with the physical solvent and thesolvent.

A twentieth embodiment can include the method of the nineteenthembodiment, wherein the gas stream further comprises water, and whereinthe method further comprises: removing at least a portion of the waterin the gas stream prior to liquefying at least the portion of the gasstream.

A twenty first embodiment can include the method of the twentiethembodiment, wherein removing at least the portion of the water in thegas stream occurs in response to contacting the gas stream with thephysical solvent.

A twenty second embodiment can include the method of the twenty firstembodiment, wherein removing at least the portion of the water in thegas stream reduces the water in the gas stream to at or below about 1 toabout 3 lb/MMscf.

A twenty third embodiment can include the method of the twenty secondembodiment, wherein removing at least the portion of the water in thegas stream occurs in a dehydration unit.

A twenty fourth embodiment can include the method of any of thenineteenth to twenty third embodiments, wherein contacting the gasstream with the physical solvent further removes at least a portion ofthe acid gas components.

A twenty fifth embodiment can include the method of any of thenineteenth to twenty fourth embodiments, wherein removing at least theportion of the C₅₊ hydrocarbons reduces a concentration of benzene,toluene, and xylene in the gas stream to at or below about 1 ppmv.

A twenty sixth embodiment can include the method of any of thenineteenth to twenty fifth embodiments, wherein removing at least theportion of the C₅₊ hydrocarbons reduces a concentration of C₅₊components in the gas stream to at or below about 0.1% by volume.

A twenty seventh embodiment can include the method of any of thenineteenth to twenty sixth embodiments, wherein removing at least theportion of the C₅₊ hydrocarbons reduces a concentration of C₆₊components in the gas stream to at or below about 150 ppmv.

A twenty eighth embodiment can include the method of any of thenineteenth to twenty seventh embodiments, wherein the gas stream has aC₂₊ composition below 3 GPM prior to being contacted with the physicalsolvent or the solvent.

A twenty ninth embodiment can include the method of any of thenineteenth to twenty eighth embodiments, wherein the physical solventcomprises dimethylether of polyethylene glycol, ethylene carbonate,propylene carbonate, N-methylpyrrolidone, glycol ethers, ethers ofpolyglycols, N-substituted morpholine, or any combination thereof.

A thirtieth embodiment can include the method of any of the nineteenthto twenty ninth embodiments, wherein contacting the gas stream with thephysical solvent and contacting the gas stream with the solvent occursat a pressure between about 900 psig and about 1500 psig.

A thirty first embodiment can include the method of any of thenineteenth to thirtieth embodiments, wherein contacting the gas streamwith the physical solvent removes between about 20% and about 40% of theC₅ hydrocarbons in the gas stream being contacted with the physicalsolvent.

A thirty second embodiment can include the method of any of thenineteenth to thirty first embodiments, wherein contacting the gasstream with the physical solvent removes between about 30% and 70% ofthe C₆ hydrocarbons in the gas stream being contacted with the physicalsolvent.

A thirty third embodiment can include the method of any of thenineteenth to thirty second embodiments, wherein contacting the gasstream with the physical solvent removes between about 90% and 99% ofthe C₇₊ hydrocarbons in the gas stream being contacted with the physicalsolvent.

A thirty fourth embodiment can include the method of any of thenineteenth to thirty third embodiments, wherein contacting the gasstream with the physical solvent removes greater than 90% of thearomatic hydrocarbons in the gas stream being contacted with thephysical solvent.

While various embodiments in accordance with the principles disclosedherein have been shown and described above, modifications thereof may bemade by one skilled in the art without departing from the spirit and theteachings of the disclosure. The embodiments described herein arerepresentative only and are not intended to be limiting. Manyvariations, combinations, and modifications are possible and are withinthe scope of the disclosure. Alternative embodiments that result fromcombining, integrating, and/or omitting features of the embodiment(s)are also within the scope of the disclosure. Accordingly, the scope ofprotection is not limited by the description set out above, but isdefined by the claims which follow, that scope including all equivalentsof the subject matter of the claims. Each and every claim isincorporated as further disclosure into the specification, and theclaims are embodiment(s) of the present invention(s). Furthermore, anyadvantages and features described above may relate to specificembodiments, but shall not limit the application of such issued claimsto processes and structures accomplishing any or all of the aboveadvantages or having any or all of the above features.

Additionally, the section headings used herein are provided forconsistency with the suggestions under 37 C.F.R. 1.77 or to otherwiseprovide organizational cues. These headings shall not limit orcharacterize the invention(s) set out in any claims that may issue fromthis disclosure. Specifically and by way of example, although theheadings might refer to a “Field,” the claims should not be limited bythe language chosen under this heading to describe the so-called field.Further, a description of a technology in the “Background” is not to beconstrued as an admission that certain technology is prior art to anyinvention(s) in this disclosure. Neither is the “Summary” to beconsidered as a limiting characterization of the invention(s) set forthin issued claims. Furthermore, any reference in this disclosure to“invention” in the singular should not be used to argue that there isonly a single point of novelty in this disclosure. Multiple inventionsmay be set forth according to the limitations of the multiple claimsissuing from this disclosure, and such claims accordingly define theinvention(s), and their equivalents, that are protected thereby. In allinstances, the scope of the claims shall be considered on their ownmerits in light of this disclosure, but should not be constrained by theheadings set forth herein.

Use of broader terms such as “comprises,” “includes,” and “having”should be understood to provide support for narrower terms such as“consisting of,” “consisting essentially of,” and “comprisedsubstantially of” Use of the terms “optionally,” “may,” “might,”“possibly,” and the like with respect to any element of an embodimentmeans that the element is not required, or alternatively, the element isrequired, both alternatives being within the scope of the embodiment(s).Also, references to examples are merely provided for illustrativepurposes, and are not intended to be exclusive.

While several embodiments have been provided in the present disclosure,it should be understood that the disclosed systems and methods may beembodied in many other specific forms without departing from the spiritor scope of the present disclosure. The present examples are to beconsidered as illustrative and not restrictive, and the intention is notto be limited to the details given herein. For example, the variouselements or components may be combined or integrated in another system,or certain features may be omitted or not implemented.

Also, techniques, systems, subsystems, and methods described andillustrated in the various embodiments as discrete or separate may becombined or integrated with other systems, modules, techniques, ormethods without departing from the scope of the present disclosure.Other items shown or discussed as directly coupled or communicating witheach other may be indirectly coupled or communicating through someinterface, device, or intermediate component, whether electrically,mechanically, or otherwise. Other examples of changes, substitutions,and alterations are ascertainable by one skilled in the art and could bemade without departing from the spirit and scope disclosed herein.

What is claimed is:
 1. A system for processing a gas stream, the systemcomprising: a physical solvent unit, wherein the physical solvent unitis configured to receive a feed gas stream, remove at least a portion ofany C₅₊ hydrocarbons in the feed gas stream using a physical solvent,and produce a cleaned gas stream comprising the feed gas stream with theportion of the C₅₊ hydrocarbons removed, wherein the physical solventunit further comprises a wash section configured for contacting the feedgas stream with water; an acid gas removal unit downstream of thephysical solvent unit, wherein the acid gas removal unit is configuredto receive the cleaned gas stream, remove at least a portion of any acidgases present in the cleaned gas stream, and produce a treated gasstream; and an LNG liquefaction unit downstream of the acid gas removalunit, wherein the LNG liquefaction unit is configured to receive thetreated gas stream and liquefy at least a portion of the hydrocarbons inthe treated gas stream.
 2. The system of claim 1, further comprising: adehydration unit downstream of the acid gas removal unit and upstream ofthe LNG liquefaction unit, wherein the dehydration unit is configured toremove at least a portion of the water present in the treated gas streamprior to the treated gas stream passing to the LNG liquefaction unit. 3.The system of claim 1, further comprising a mercury removal unitconfigured to remove mercury in the treated gas.
 4. The system of claim1, wherein the physical solvent unit is configured to produce thecleaned gas stream having a benzene, toluene, and xylene compositionbelow about 1 ppmv.
 5. The system of claim 1, wherein the physicalsolvent unit is configured to produce the cleaned gas stream having aC₅₊ composition below about 0.1% by volume.
 6. The system of claim 1,wherein the physical solvent unit is configured to produce the cleanedgas stream having a C₆₊ composition below about 150 ppmv.
 7. The systemof claim 1, further comprising the physical solvent, wherein thephysical solvent comprises dimethylether of polyethylene glycol,ethylene carbonate, propylene carbonate, N-methylpyrrolidone, glycolethers, ethers of polyglycols, N-substituted morpholine, or anycombination thereof.
 8. The system of claim 1, wherein the physicalsolvent unit is configured to remove at least a portion of any waterpresent in the feed gas stream.
 9. The system of claim 1, furthercomprising feed gas in the feed gas stream, wherein the feed gas has aC₃₊ composition below about 2 to 3 GPM.
 10. The system of claim 1,wherein the physical solvent unit is configured to produce the cleanedgas stream having a water composition at or below about 1 lb/MMscf. 11.The system of claim 1, wherein the physical solvent unit is configuredto contact the feed gas stream with the physical solvent and then withthe water.
 12. A system for processing a gas stream, the systemcomprising: an acid gas removal unit, wherein the acid gas removal unitis configured to receive a feed gas stream, wherein the feed gas streamcomprises C₁ hydrocarbons, C₂ hydrocarbons, C₃ hydrocarbons, C₄hydrocarbons, C₅₊ hydrocarbons, and/or acid gas components, remove atleast a portion of any acid gases present in the feed gas stream, andproduce a cleaned gas stream, wherein the cleaned gas stream comprisesC₁ hydrocarbons, C₂ hydrocarbons, C₃ hydrocarbons, C₄ hydrocarbons,and/or C₅₊ hydrocarbons; a physical solvent unit downstream of the acidgas removal unit, wherein the physical solvent unit is configured toreceive the cleaned gas stream, remove at least a portion of any C₅₊hydrocarbons in the cleaned gas stream, and produce a treated gas streamcomprising the cleaned gas stream with the portion of the C₅₊hydrocarbons removed, wherein the physical solvent unit furthercomprises a wash section configured for contacting the cleaned gasstream with water; and an LNG liquefaction unit downstream of thephysical solvent unit, wherein the LNG liquefaction unit is configuredto receive the treated gas stream and liquefy at least a portion of thehydrocarbons in the treated gas stream.
 13. The system of claim 12,wherein the physical solvent unit is configured to contact the cleanedgas stream with a physical solvent and then with the water.
 14. Thesystem of claim 12, further comprising: a dehydration unit downstream ofthe acid gas removal unit and upstream of the LNG liquefaction unit,wherein the dehydration unit is configured to receive the treated gasstream and remove at least a portion of the water present in the treatedgas stream prior to the cleaned gas stream passing to the LNGliquefaction unit.
 15. The system of claim 12, wherein the physicalsolvent unit is configured to produce the cleaned gas stream having abenzene, toluene, and xylene composition below about 1 ppmv.
 16. Thesystem of claim 12, wherein the physical solvent unit is configured toproduce the cleaned gas stream having a C₅₊ composition below about 0.1%by volume.
 17. The system of claim 12, wherein the physical solvent unitis configured to produce the cleaned gas stream having a C₆₊ compositionbelow about 150 ppmv.
 18. The system of claim 12, further comprising aphysical solvent disposed in the physical solvent unit, wherein thephysical solvent comprises dimethylether of polyethylene glycol,ethylene carbonate, propylene carbonate, N-methylpyrrolidone, glycolethers, ethers of polyglycols, N-substituted morpholine, or anycombination thereof.
 19. The system of claim 12, further comprising thefeed gas, wherein the feed gas has a C₂+ composition below about 2 to 3GPM.
 20. The system of claim 12, wherein the physical solvent unit isconfigured to remove at least a portion of any water present in the feedgas; and/or wherein the physical solvent unit is configured to producethe cleaned gas stream having a water composition at or below about 1lb/MMscf.